Methods and systems for drilling

ABSTRACT

Systems and methods of controlling drilling operations including Sliding With Indexing For Toolface (SWIFT) and Variable Weight Drilling (VWD) techniques. The methods and systems may include systems and devices for controlling the drilling operations, including systems and devices capable of automatically determining drilling parameters and setting operating parameters for drilling in a wellbore. The systems and methods may also determine a change in weight on bit and/or toolface, determine a timeframe for a weight on bit to be delivered to the bit, and/or determine a spindle change to modify the toolface. The systems and methods may also send control signals to apply the spindle change and/or block velocity change to correct any detected or anticipated toolface error.

CROSS-REFERENCES TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. ProvisionalApplication No. 63/069,601, filed Aug. 24, 2020, the entire contents ofwhich is hereby incorporated for all purposes in its entirety.

FIELD OF THE DISCLOSURE

The present disclosure provides systems and methods useful for drillinga well, such as an oil and gas well. The systems and methods can becomputer-implemented using processor executable instructions forexecution on a processor and can accordingly be executed with aprogrammed computer system.

DESCRIPTION OF THE RELATED ART

Drilling a borehole for the extraction of minerals has become anincreasingly complicated operation due to the increased depth andcomplexity of many boreholes, including the complexity added bydirectional drilling. Drilling is an expensive operation and errors indrilling add to the cost and, in some cases, drilling errors maypermanently lower the output of a well for years into the future.Conventional technologies and methods may not adequately address thecomplicated nature of drilling, and may not be capable of gathering andprocessing various information from downhole sensors and surface controlsystems in a timely manner, in order to improve drilling operations andminimize drilling errors.

In the oil and gas industry, extraction of hydrocarbon natural resourcesis done by physically drilling a hole to a reservoir where thehydrocarbon natural resources are trapped. The hydrocarbon naturalresources can be up to 10,000 feet or more below the ground surface andbe buried under various layers of geological formations. Drillingoperations can be conducted by having a rotating drill bit mounted on abottom hole assembly (BHA) that gives direction to the drill bit forcutting through geological formations and enabled steerable drilling.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention and itsfeatures and advantages, reference is now made to the followingdescription, taken in conjunction with the accompanying drawings, inwhich:

FIG. 1 is a depiction of a drilling system for drilling a borehole;

FIG. 2 is a depiction of a drilling environment including the drillingsystem for drilling a borehole;

FIG. 3 is a depiction of a borehole generated in the drillingenvironment;

FIG. 4 is a depiction of a drilling architecture including the drillingenvironment;

FIG. 5 is a depiction of rig control systems included in the drillingsystem;

FIG. 6 is a depiction of algorithm modules used by the rig controlsystems;

FIG. 7 is a depiction of a steering control process used by the rigcontrol systems;

FIG. 8 is a depiction of a graphical user interface provided by the rigcontrol systems;

FIG. 9 is a depiction of a guidance control loop performed by the rigcontrol systems;

FIG. 10 is a depiction of a controller usable by the rig controlsystems;

FIG. 11 is a diagram illustrating the Stockhausen Effect.

FIG. 12 is an illustration of toolface values over time.

FIG. 13 is an illustration of the cosine function of the change intoolface over time.

FIG. 14 is an illustration of the cosine function of the change intoolface over time and the weight on bit over time.

FIG. 15 is an illustration of the effects of the weight on bit changeson time on the toolface value over time.

FIG. 16 is an illustration of the cosine of toolface and reactive torqueover time (together with the cosine of change in toolface and the weighton bit changes over time), showing an average cosine(toolface) as well.

FIG. 17 is an illustration of a minimum yield for drilling when theweight on bit arrives 90 degrees from the spindle phase.

FIG. 18 is an illustration of a maximum yield for drilling when theweight on bit arrives 180 degrees from the spindle phase.

FIG. 19 is a block diagram illustrating the steps that may be taken withthe VWD methods and systems disclosed herein.

DESCRIPTION

In the following description, details are set forth by way of example tofacilitate discussion of the disclosed subject matter. It is noted,however, that the disclosed embodiments are exemplary and not exhaustiveof all possible embodiments.

Throughout this disclosure, a hyphenated form of a reference numeralrefers to a specific instance of an element and the un-hyphenated formof the reference numeral refers to the element generically orcollectively. Thus, as an example (not shown in the drawings), device“12-1” refers to an instance of a device class, which may be referred tocollectively as devices “12” and any one of which may be referred togenerically as a device “12”. In the figures and the description, likenumerals are intended to represent like elements.

Drilling a well typically involves a substantial amount of humandecision-making during the drilling process. For example, geologists anddrilling engineers use their knowledge, experience, and the availableinformation to make decisions on how to plan the drilling operation, howto accomplish the drilling plan, and how to handle issues that ariseduring drilling. However, even the best geologists and drillingengineers perform some guesswork due to the unique nature of eachborehole. Furthermore, a directional human driller performing thedrilling may have drilled other boreholes in the same region and so mayhave some similar experience. However, during drilling operations, amultitude of input information and other factors may affect a drillingdecision being made by a human operator or specialist, such that theamount of information may overwhelm the cognitive ability of the humanto properly consider and factor into the drilling decision. Furthermore,the quality or the error involved with the drilling decision may improvewith larger amounts of input data being considered, for example, such asformation data from a large number of offset wells. For these reasons,human specialists may be unable to achieve desirable drilling decisions,particularly when such drilling decisions are made under timeconstraints, such as during drilling operations when continuation ofdrilling is dependent on the drilling decision and, thus, the entiredrilling rig waits idly for the next drilling decision. Furthermore,human decision-making for drilling decisions can result in expensivemistakes, because drilling errors can add significant cost to drillingoperations. In some cases, drilling errors may permanently lower theoutput of a well, resulting in substantial long term economic losses dueto the lost output of the well.

Therefore, the well plan may be updated based on new stratigraphicinformation from the wellbore, as it is being drilled. Thisstratigraphic information can be gained on one hand from measurementwhile drilling (MWD) and logging while drilling (LWD) sensor data, butcould also include other reference well data, such as drilling dynamicsdata or sensor data giving information, for example, on the hardness ofthe rock in individual strata layers being drilled through.

Referring now to the drawings, Referring to FIG. 1 , a drilling system100 is illustrated in one embodiment as a top drive system. As shown,the drilling system 100 includes a derrick 132 on the surface 104 of theearth and is used to drill a borehole 106 into the earth. Typically,drilling system 100 is used at a location corresponding to a geographicformation 102 in the earth that is known.

In FIG. 1 , derrick 132 includes a crown block 134 to which a travellingblock 136 is coupled via a drilling line 138. In drilling system 100, atop drive 140 is coupled to travelling block 136 and may providerotational force for drilling. A saver sub 142 may sit between the topdrive 140 and a drill pipe 144 that is part of a drill string 146. Topdrive 140 may rotate drill string 146 via the saver sub 142, which inturn may rotate a drill bit 148 of a bottom hole assembly (BHA) 149 inborehole 106 passing through formation 102. Also visible in drillingsystem 100 is a rotary table 162 that may be fitted with a masterbushing 164 to hold drill string 146 when not rotating.

A mud pump 152 may direct a fluid mixture 153 (e.g., a mud mixture) froma mud pit 154 into drill string 146. Mud pit 154 is shown schematicallyas a container, but it is noted that various receptacles, tanks, pits,or other containers may be used. Mud 153 may flow from mud pump 152 intoa discharge line 156 that is coupled to a rotary hose 158 by a standpipe160. Rotary hose 158 may then be coupled to top drive 140, whichincludes a passage for mud 153 to flow into borehole 106 via drillstring 146 from where mud 153 may emerge at drill bit 148. Mud 153 maylubricate drill bit 148 during drilling and, due to the pressuresupplied by mud pump 152, mud 153 may return via borehole 106 to surface104.

In drilling system 100, drilling equipment (see also FIG. 5 ) is used toperform the drilling of borehole 106, such as top drive 140 (or rotarydrive equipment) that couples to drill string 146 and BHA 149 and isconfigured to rotate drill string 146 and apply pressure to drill bit148. Drilling system 100 may include control systems such as aWOB/differential pressure control system 522, a positional/rotarycontrol system 524, a fluid circulation control system 526, and a sensorsystem 528, as further described below with respect to FIG. 5 . Thecontrol systems may be used to monitor and change drilling rig settings,such as the WOB or differential pressure to alter the ROP or the radialorientation of the toolface, change the flow rate of drilling mud, andperform other operations. Sensor system 528 may be for obtaining sensordata about the drilling operation and drilling system 100, including thedownhole equipment. For example, sensor system 528 may include MWD orlogging while drilling (LWD) tools for acquiring information, such astoolface and formation logging information, that may be saved for laterretrieval, transmitted with or without a delay using any of variouscommunication means (e.g., wireless, wireline, or mud pulse telemetry),or otherwise transferred to steering control system 168. As used herein,an MWD tool is enabled to communicate downhole measurements withoutsubstantial delay to the surface 104, such as using mud pulse telemetry,while a LWD tool is equipped with an internal memory that storesmeasurements when downhole and can be used to download a stored log ofmeasurements when the LWD tool is at the surface 104. The internalmemory in the LWD tool may be a removable memory, such as a universalserial bus (USB) memory device or another removable memory device. It isnoted that certain downhole tools may have both MWD and LWDcapabilities. Such information acquired by sensor system 528 may includeinformation related to hole depth, bit depth, inclination angle, azimuthangle, true vertical depth, gamma count, standpipe pressure, mud flowrate, rotary rotations per minute (RPM), bit speed, ROP, WOB, amongother information. It is noted that all or part of sensor system 528 maybe incorporated into a control system, or in another component of thedrilling equipment. As drilling system 100 can be configured in manydifferent implementations, it is noted that different control systemsand subsystems may be used.

Sensing, detection, measurement, evaluation, storage, alarm, and otherfunctionality may be incorporated into a downhole tool 166 or BHA 149 orelsewhere along drill string 146 to provide downhole surveys of borehole106. Accordingly, downhole tool 166 may be an MWD tool or a LWD tool orboth, and may accordingly utilize connectivity to the surface 104, localstorage, or both. In different implementations, gamma radiation sensors,magnetometers, accelerometers, and other types of sensors may be usedfor the downhole surveys. Although downhole tool 166 is shown insingular in drilling system 100, it is noted that multiple instances(not shown) of downhole tool 166 may be located at one or more locationsalong drill string 146.

In some embodiments, formation detection and evaluation functionalitymay be provided via a steering control system 168 on the surface 104.Steering control system 168 may be located in proximity to derrick 132or may be included with drilling system 100. In other embodiments,steering control system 168 may be remote from the actual location ofborehole 106 (see also FIG. 4 ). For example, steering control system168 may be a stand-alone system or may be incorporated into othersystems included with drilling system 100.

In operation, steering control system 168 may be accessible via acommunication network (see also FIG. 10 ), and may accordingly receiveformation information via the communication network. In someembodiments, steering control system 168 may use the evaluationfunctionality to provide corrective measures, such as a convergence planto overcome an error in the well trajectory of borehole 106 with respectto a reference, or a planned well trajectory. The convergence plans orother corrective measures may depend on a determination of the welltrajectory, and therefore, may be improved in accuracy using surfacesteering, as disclosed herein.

In particular embodiments, at least a portion of steering control system168 may be located in downhole tool 166 (not shown). In someembodiments, steering control system 168 may communicate with a separatecontroller (not shown) located in downhole tool 166. In particular,steering control system 168 may receive and process measurementsreceived from downhole surveys, and may perform the calculationsdescribed herein for surface steering using the downhole surveys andother information referenced herein.

In drilling system 100, to aid in the drilling process, data iscollected from borehole 106, such as from sensors in BHA 149, downholetool 166, or both. The collected data may include the geologicalcharacteristics of formation 102 in which borehole 106 was formed, theattributes of drilling system 100, including BHA 149, and drillinginformation such as weight-on-bit (WOB), drilling speed, and otherinformation pertinent to the formation of borehole 106. The drillinginformation may be associated with a particular depth or anotheridentifiable marker to index collected data. For example, the collecteddata for borehole 106 may capture drilling information indicating thatdrilling of the well from 1,000 feet to 1,200 feet occurred at a firstrate of penetration (ROP) through a first rock layer with a first WOB,while drilling from 1,200 feet to 1,500 feet occurred at a second ROPthrough a second rock layer with a second WOB (see also FIG. 2 ). Insome applications, the collected data may be used to virtually recreatethe drilling process that created borehole 106 in formation 102, such asby displaying a computer simulation of the drilling process. Theaccuracy with which the drilling process can be recreated depends on alevel of detail and accuracy of the collected data, including collecteddata from a downhole survey of the well trajectory.

The collected data may be stored in a database that is accessible via acommunication network for example. In some embodiments, the databasestoring the collected data for borehole 106 may be located locally atdrilling system 100, at a drilling hub that supports a plurality ofdrilling systems 100 in a region, or at a database server accessibleover the communication network that provides access to the database (seealso FIG. 4 ). At drilling system 100, the collected data may be storedat the surface 104 or downhole in drill string 146, such as in a memorydevice included with BHA 149 (see also FIG. 10 ). Alternatively, atleast a portion of the collected data may be stored on a removablestorage medium, such as using steering control system 168 or BHA 149,that is later coupled to the database in order to transfer the collecteddata to the database, which may be manually performed at certainintervals, for example.

In FIG. 1 , steering control system 168 is located at or near thesurface 104 where borehole 106 is being drilled. Steering control system168 may be coupled to equipment used in drilling system 100 and may alsobe coupled to the database, whether the database is physically locatedlocally, regionally, or centrally (see also FIGS. 4 and 5 ).Accordingly, steering control system 168 may collect and record variousinputs, such as measurement data from a magnetometer and anaccelerometer that may also be included with BHA 149.

Steering control system 168 may further be used as a surface steerablesystem, along with the database, as described above. The surfacesteerable system may enable an operator to plan and control drillingoperations while drilling is being performed. The surface steerablesystem may itself also be used to perform certain drilling operations,such as controlling certain control systems that, in turn, control theactual equipment in drilling system 100 (see also FIG. 5 ). The controlof drilling equipment and drilling operations by steering control system168 may be manual, manual-assisted, semi-automatic, or automatic, indifferent embodiments.

Manual control may involve direct control of the drilling rig equipment,albeit with certain safety limits to prevent unsafe or undesired actionsor collisions of different equipment. To enable manual-assisted control,steering control system 168 may present various information, such asusing a graphical user interface (GUI) displayed on a display device(see FIG. 8 ), to a human operator, and may provide controls that enablethe human operator to perform a control operation. The informationpresented to the user may include live measurements and feedback fromthe drilling rig and steering control system 168, or the drilling rigitself, and may further include limits and safety-related elements toprevent unwanted actions or equipment states, in response to a manualcontrol command entered by the user using the GUI.

To implement semi-automatic control, steering control system 168 mayitself propose or indicate to the user, such as via the GUI, that acertain control operation, or a sequence of control operations, shouldbe performed at a given time. Then, steering control system 168 mayenable the user to imitate the indicated control operation or sequenceof control operations, such that once manually started, the indicatedcontrol operation or sequence of control operations is automaticallycompleted. The limits and safety features mentioned above for manualcontrol would still apply for semi-automatic control. It is noted thatsteering control system 168 may execute semi-automatic control using asecondary processor, such as an embedded controller that executes undera real-time operating system (RTOS), that is under the control andcommand of steering control system 168. To implement automatic control,the step of manual starting the indicated control operation or sequenceof operations is eliminated, and steering control system 168 may proceedwith a passive notification to the user of the actions taken.

In order to implement various control operations, steering controlsystem 168 may perform (or may cause to be performed) various inputoperations, processing operations, and output operations. The inputoperations performed by steering control system 168 may result inmeasurements or other input information being made available for use inany subsequent operations, such as processing or output operations. Theinput operations may accordingly provide the input information,including feedback from the drilling process itself, to steering controlsystem 168. The processing operations performed by steering controlsystem 168 may be any processing operation associated with surfacesteering, as disclosed herein. The output operations performed bysteering control system 168 may involve generating output informationfor use by external entities, or for output to a user, such as in theform of updated elements in the GUI, for example. The output informationmay include at least some of the input information, enabling steeringcontrol system 168 to distribute information among various entities andprocessors.

In particular, the operations performed by steering control system 168may include operations such as receiving drilling data representing adrill path, receiving other drilling parameters, calculating a drillingsolution for the drill path based on the received data and otheravailable data (e.g., rig characteristics), implementing the drillingsolution at the drilling rig, monitoring the drilling process to gaugewhether the drilling process is within a defined margin of error of thedrill path, and calculating corrections for the drilling process if thedrilling process is outside of the margin of error.

Accordingly, steering control system 168 may receive input informationeither before drilling, during drilling, or after drilling of borehole106. The input information may comprise measurements from one or moresensors, as well as survey information collected while drilling borehole106. The input information may also include a well plan, a regionalformation history, drilling engineer parameters, downhole toolface/inclination information, downhole tool gamma/resistivityinformation, economic parameters, reliability parameters, among variousother parameters. Some of the input information, such as the regionalformation history, may be available from a drilling hub 410, which mayhave respective access to a regional drilling database (DB) 412 (seeFIG. 4 ). Other input information may be accessed or uploaded from othersources to steering control system 168. For example, a web interface maybe used to interact directly with steering control system 168 to uploadthe well plan or drilling parameters.

As noted, the input information may be provided to steering controlsystem 168. After processing by steering control system 168, steeringcontrol system 168 may generate control information that may be outputto drilling rig 210 (e.g., to rig controls 520 that control drillingequipment 530, see also FIGS. 2 and 5 ). Drilling rig 210 may providefeedback information using rig controls 520 to steering control system168. The feedback information may then serve as input information tosteering control system 168, thereby enabling steering control system168 to perform feedback loop control and validation. Accordingly,steering control system 168 may be configured to modify its outputinformation to drilling rig 210, in order to achieve the desiredresults, which are indicated in the feedback information. The outputinformation generated by steering control system 168 may includeindications to modify one or more drilling parameters, the direction ofdrilling, the drilling mode, among others. In certain operational modes,such as semi-automatic or automatic, steering control system 168 maygenerate output information indicative of instructions to rig controls520 to enable automatic drilling using the latest location of BHA 149.Therefore, an improved accuracy in the determination of the location ofBHA 149 may be provided using steering control system 168, along withthe methods and operations for surface steering disclosed herein.

Referring now to FIG. 2 , a drilling environment 200 is depictedschematically and is not drawn to scale or perspective. In particular,drilling environment 200 may illustrate additional details with respectto formation 102 below the surface 104 in drilling system 100 shown inFIG. 1 . In FIG. 2 , drilling rig 210 may represent various equipmentdiscussed above with respect to drilling system 100 in FIG. 1 that islocated at the surface 104.

In drilling environment 200, it may be assumed that a drilling plan(also referred to as a well plan) has been formulated to drill borehole106 extending into the ground to a true vertical depth (TVD) 266 andpenetrating several subterranean strata layers. Borehole 106 is shown inFIG. 2 extending through strata layers 268-1 and 270-1, whileterminating in strata layer 272-1. Accordingly, as shown, borehole 106does not extend or reach underlying strata layers 274-1 and 276-1. Atarget area 280 specified in the drilling plan may be located in stratalayer 272-1 as shown in FIG. 2 . Target area 280 may represent a desiredendpoint of borehole 106, such as a hydrocarbon producing area indicatedby strata layer 272-1. It is noted that target area 280 may be of anyshape and size, and may be defined using various different methods andinformation in different embodiments. In some instances, target area 280may be specified in the drilling plan using subsurface coordinates, orreferences to certain markers, that indicate where borehole 106 is to beterminated. In other instances, target area may be specified in thedrilling plan using a depth range within which borehole 106 is toremain. For example, the depth range may correspond to strata layer272-1. In other examples, target area 280 may extend as far as can berealistically drilled. For example, when borehole 106 is specified tohave a horizontal section with a goal to extend into strata layer 172 asfar as possible, target area 280 may be defined as strata layer 272-1itself and drilling may continue until some other physical limit isreached, such as a property boundary or a physical limitation to thelength of drill string 146.

Also visible in FIG. 2 is a fault line 278 that has resulted in asubterranean discontinuity in the fault structure. Specifically, stratalayers 268, 270, 272, 274, and 276 have portions on either side of faultline 278. On one side of fault line 278, where borehole 106 is located,strata layers 268-1, 270-1, 272-1, 274-1, and 276-1 are unshifted byfault line 278. On the other side of fault line 278, strata layers268-2, 270-2, 272-2, 274-2, and 276-2 are shifted downwards by faultline 278.

Current drilling operations frequently include directional drilling toreach a target, such as target area 280. The use of directional drillinghas been found to generally increase an overall amount of productionvolume per well, but also may lead to significantly higher productionrates per well, which are both economically desirable. As shown in FIG.2 , directional drilling may be used to drill the horizontal portion ofborehole 106, which increases an exposed length of borehole 106 withinstrata layer 272-1, and which may accordingly be beneficial forhydrocarbon extraction from strata layer 272-1. Directional drilling mayalso be used alter an angle of borehole 106 to accommodate subterraneanfaults, such as indicated by fault line 278 in FIG. 1 . Other benefitsthat may be achieved using directional drilling include sidetracking offof an existing well to reach a different target area or a missed targetarea, drilling around abandoned drilling equipment, drilling intootherwise inaccessible or difficult to reach locations (e.g.,underpopulated areas or bodies of water), providing a relief well for anexisting well, and increasing the capacity of a well by branching offand having multiple boreholes extending in different directions or atdifferent vertical positions for the same well. Directional drilling isoften not limited to a straight horizontal borehole 106, but may involvestaying within a strata layer that varies in depth and thickness asillustrated by strata layer 272. As such, directional drilling mayinvolve multiple vertical adjustments that complicate the trajectory ofborehole 106.

Referring now to FIG. 3 , one embodiment of a portion of borehole 106 isshown in further detail. Using directional drilling for horizontaldrilling may introduce certain challenges or difficulties that may notbe observed during vertical drilling of borehole 106. For example, ahorizontal portion 318 of borehole 106 may be started from a verticalportion 310. In order to make the transition from vertical tohorizontal, a curve may be defined that specifies a so-called “build up”section 316. Build up section 316 may begin at a kick off point 312 invertical portion 310 and may end at a begin point 314 of horizontalportion 318. The change in inclination angle in build up section 316 permeasured length drilled is referred to herein as a “build rate” and maybe defined in degrees per one hundred feet drilled. For example, thebuild rate may have a value of 6°/100 ft., indicating that there is asix degree change in inclination angle for every one hundred feetdrilled. The build rate for a particular build up section may remainrelatively constant or may vary.

The build rate used for any given build up section may depend on variousfactors, such as properties of the formation (i.e., strata layers)through which borehole 106 is to be drilled, the trajectory of borehole106, the particular pipe and drill collars/BHA components used (e.g.,length, diameter, flexibility, strength, mud motor bend setting, anddrill bit), the mud type and flow rate, the specified horizontaldisplacement, stabilization, and inclination angle, among other factors.An overly aggressive built rate can cause problems such as severedoglegs (e.g., sharp changes in direction in the borehole) that may makeit difficult or impossible to run casing or perform other operations inborehole 106. Depending on the severity of any mistakes made duringdirectional drilling, borehole 106 may be enlarged or drill bit 146 maybe backed out of a portion of borehole 106 and redrilled along adifferent path. Such mistakes may be undesirable due to the additionaltime and expense involved. However, if the built rate is too cautious,additional overall time may be added to the drilling process, becausedirectional drilling generally involves a lower ROP than straightdrilling. Furthermore, directional drilling for a curve is morecomplicated than vertical drilling and the possibility of drillingerrors increases with directional drilling (e.g., overshoot andundershoot that may occur while trying to keep drill bit 148 on theplanned trajectory).

Two modes of drilling, referred to herein as “rotating” and “sliding”,are commonly used to form borehole 106. Rotating, also called “rotarydrilling”, uses top drive 140 or rotary table 162 to rotate drill string146. Rotating may be used when drilling occurs along a straighttrajectory, such as for vertical portion 310 of borehole 106. Sliding,also called “steering” or “directional drilling” as noted above,typically uses a mud motor located downhole at BHA 149. The mud motormay have an adjustable bent housing and is not powered by rotation ofdrill string 146. Instead, the mud motor uses hydraulic power derivedfrom the pressurized drilling mud that circulates along borehole 106 toand from the surface 104 to directionally drill borehole 106 in build upsection 316.

Thus, sliding is used in order to control the direction of the welltrajectory during directional drilling. A method to perform a slide mayinclude the following operations. First, during vertical or straightdrilling, the rotation of drill string 146 is stopped. Based on feedbackfrom measuring equipment, such as from downhole tool 166, adjustmentsmay be made to drill string 146, such as using top drive 140 to applyvarious combinations of torque, WOB, and vibration, among otheradjustments. The adjustments may continue until a tool face is confirmedthat indicates a direction of the bend of the mud motor is oriented to adirection of a desired deviation (i.e., build rate) of borehole 106.Once the desired orientation of the mud motor is attained, WOB to thedrill bit is increased, which causes the drill bit to move in thedesired direction of deviation. Once sufficient distance and angle havebeen built up in the curved trajectory, a transition back to rotatingmode can be accomplished by rotating drill string 146 again. Therotation of drill string 146 after sliding may neutralize thedirectional deviation caused by the bend in the mud motor due to thecontinuous rotation around a centerline of borehole 106.

Referring now to FIG. 4 , a drilling architecture 400 is illustrated indiagram form. As shown, drilling architecture 400 depicts a hierarchicalarrangement of drilling hubs 410 and a central command 414, to supportthe operation of a plurality of drilling rigs 210 in different regions402. Specifically, as described above with respect to FIGS. 1 and 2 ,drilling rig 210 includes steering control system 168 that is enabled toperform various drilling control operations locally to drilling rig 210.When steering control system 168 is enabled with network connectivity,certain control operations or processing may be requested or queried bysteering control system 168 from a remote processing resource. As shownin FIG. 4 , drilling hubs 410 represent a remote processing resource forsteering control system 168 located at respective regions 402, whilecentral command 414 may represent a remote processing resource for bothdrilling hub 410 and steering control system 168.

Specifically, in a region 402-1, a drilling hub 410-1 may serve as aremote processing resource for drilling rigs 210 located in region402-1, which may vary in number and are not limited to the exemplaryschematic illustration of FIG. 4 . Additionally, drilling hub 410-1 mayhave access to a regional drilling DB 412-1, which may be local todrilling hub 410-1. Additionally, in a region 402-2, a drilling hub410-2 may serve as a remote processing resource for drilling rigs 210located in region 402-2, which may vary in number and are not limited tothe exemplary schematic illustration of FIG. 4 . Additionally, drillinghub 410-2 may have access to a regional drilling DB 412-2, which may belocal to drilling hub 410-2.

In FIG. 4 , respective regions 402 may exhibit the same or similargeological formations. Thus, reference wells, or offset wells, may existin a vicinity of a given drilling rig 210 in region 402, or where a newwell is planned in region 402. Furthermore, multiple drilling rigs 210may be actively drilling concurrently in region 402, and may be indifferent stages of drilling through the depths of formation stratalayers at region 402. Thus, for any given well being drilled by drillingrig 210 in a region 402, survey data from the reference wells or offsetwells may be used to create the well plan, and may be used for surfacesteering, as disclosed herein. In some implementations, survey data orreference data from a plurality of reference wells may be used toimprove drilling performance, such as by reducing an error in estimatingTVD or a position of BHA 149 relative to one or more strata layers, aswill be described in further detail herein. Additionally, survey datafrom recently drilled wells, or wells still currently being drilled,including the same well, may be used for reducing an error in estimatingTVD or a position of BHA 149 relative to one or more strata layers.

Also shown in FIG. 4 is central command 414, which has access to centraldrilling DB 416, and may be located at a centralized command center thatis in communication with drilling hubs 410 and drilling rigs 210 invarious regions 402. The centralized command center may have the abilityto monitor drilling and equipment activity at any one or more drillingrigs 210. In some embodiments, central command 414 and drilling hubs 412may be operated by a commercial operator of drilling rigs 210 as aservice to customers who have hired the commercial operator to drillwells and provide other drilling-related services.

In FIG. 4 , it is particularly noted that central drilling DB 416 may bea central repository that is accessible to drilling hubs 410 anddrilling rigs 210. Accordingly, central drilling DB 416 may storeinformation for various drilling rigs 210 in different regions 402. Insome embodiments, central drilling DB 416 may serve as a backup for atleast one regional drilling DB 412, or may otherwise redundantly storeinformation that is also stored on at least one regional drilling DB412. In turn, regional drilling DB 412 may serve as a backup orredundant storage for at least one drilling rig 210 in region 402. Forexample, regional drilling DB 412 may store information collected bysteering control system 168 from drilling rig 210.

In some embodiments, the formulation of a drilling plan for drilling rig210 may include processing and analyzing the collected data in regionaldrilling DB 412 to create a more effective drilling plan. Furthermore,once the drilling has begun, the collected data may be used inconjunction with current data from drilling rig 210 to improve drillingdecisions. As noted, the functionality of steering control system 168may be provided at drilling rig 210, or may be provided, at least inpart, at a remote processing resource, such as drilling hub 410 orcentral command 414.

As noted, steering control system 168 may provide functionality as asurface steerable system for controlling drilling rig 210. Steeringcontrol system 168 may have access to regional drilling DB 412 andcentral drilling DB 416 to provide the surface steerable systemfunctionality. As will be described in greater detail below, steeringcontrol system 168 may be used to plan and control drilling operationsbased on input information, including feedback from the drilling processitself. Steering control system 168 may be used to perform operationssuch as receiving drilling data representing a drill trajectory andother drilling parameters, calculating a drilling solution for the drilltrajectory based on the received data and other available data (e.g.,rig characteristics), implementing the drilling solution at drilling rig210, monitoring the drilling process to gauge whether the drillingprocess is within a margin of error that is defined for the drilltrajectory, or calculating corrections for the drilling process if thedrilling process is outside of the margin of error.

Referring now to FIG. 5 , an example of rig control systems 500 isillustrated in schematic form. It is noted that rig control systems 500may include fewer or more elements than shown in FIG. 5 in differentembodiments. As shown, rig control systems 500 includes steering controlsystem 168 and drilling rig 210. Specifically, steering control system168 is shown with logical functionality including an autodriller 510, abit guidance 512, and an autoslide 514. Drilling rig 210 ishierarchically shown including rig controls 520, which provide securecontrol logic and processing capability, along with drilling equipment530, which represents the physical equipment used for drilling atdrilling rig 210. As shown , rig controls 520 include WOB/differentialpressure control system 522, positional/rotary control system 524, fluidcirculation control system 526, and sensor system 528, while drillingequipment 530 includes a draw works/snub 532, top drive 140, a mudpumping 536, and an MWD/wireline 538.

Steering control system 168 represent an instance of a processor havingan accessible memory storing instructions executable by the processor,such as an instance of controller 1000 shown in FIG. 10 . Also,WOB/differential pressure control system 522, positional/rotary controlsystem 524, and fluid circulation control system 526 may each representan instance of a processor having an accessible memory storinginstructions executable by the processor, such as an instance ofcontroller 1000 shown in FIG. 10 , but for example, in a configurationas a programmable logic controller (PLC) that may not include a userinterface but may be used as an embedded controller. Accordingly, it isnoted that each of the systems included in rig controls 520 may be aseparate controller, such as a PLC, and may autonomously operate, atleast to a degree. Steering control system 168 may represent hardwarethat executes instructions to implement a surface steerable system thatprovides feedback and automation capability to an operator, such as adriller. For example, steering control system 168 may cause autodriller510, bit guidance 512 (also referred to as a bit guidance system (BGS)),and autoslide 514 (among others, not shown) to be activated and executedat an appropriate time during drilling. In particular implementations,steering control system 168 may be enabled to provide a user interfaceduring drilling, such as the user interface 850 depicted and describedbelow with respect to FIG. 8 . Accordingly, steering control system 168may interface with rig controls 520 to facilitate manual, assistedmanual, semi-automatic, and automatic operation of drilling equipment530 included in drilling rig 210. It is noted that rig controls 520 mayalso accordingly be enabled for manual or user-controlled operation ofdrilling, and may include certain levels of automation with respect todrilling equipment 530.

In rig control systems 500 of FIG. 5 , WOB/differential pressure controlsystem 522 may be interfaced with draw works/snubbing unit 532 tocontrol WOB of drill string 146. Positional/rotary control system 524may be interfaced with top drive 140 to control rotation of drill string146. Fluid circulation control system 526 may be interfaced with mudpumping 536 to control mud flow and may also receive and decode mudtelemetry signals. Sensor system 528 may be interfaced with MWD/wireline538, which may represent various BHA sensors and instrumentationequipment, among other sensors that may be downhole or at the surface.

In rig control systems 500, autodriller 510 may represent an automatedrotary drilling system and may be used for controlling rotary drilling.Accordingly, autodriller 510 may enable automate operation of rigcontrols 520 during rotary drilling, as indicated in the well plan. Bitguidance 512 may represent an automated control system to monitor andcontrol performance and operation drilling bit 148.

In rig control systems 500, autoslide 514 may represent an automatedslide drilling system and may be used for controlling slide drilling.Accordingly, autoslide 514 may enable automate operation of rig controls520 during a slide, and may return control to steering control system168 for rotary drilling at an appropriate time, as indicated in the wellplan. In particular implementations, autoslide 514 may be enabled toprovide a user interface during slide drilling to specifically monitorand control the slide. For example, autoslide 514 may rely on bitguidance 512 for orienting a tool face and on autodriller 510 to set WOBor control rotation or vibration of drill string 146.

FIG. 6 illustrates one embodiment of control algorithm modules 600 usedwith steering control system 168. The control algorithm modules 600 ofFIG. 6 include: a slide control executor 650 that is responsible formanaging the execution of the slide control algorithms; a slide controlconfiguration provider 652 that is responsible for validating,maintaining, and providing configuration parameters for the othersoftware modules; a BHA & pipe specification provider 654 that isresponsible for managing and providing details of BHA 149 and drillstring 146 characteristics; a borehole geometry model 656 that isresponsible for keeping track of the borehole geometry and providing arepresentation to other software modules; a top drive orientation impactmodel 658 that is responsible for modeling the impact that changes tothe angular orientation of top drive 140 have had on the tool facecontrol; a top drive oscillator impact model 660 that is responsible formodeling the impact that oscillations of top drive 140 has had on thetool face control; an ROP impact model 662 that is responsible formodeling the effect on the tool face control of a change in ROP or acorresponding ROP set point; a WOB impact model 664 that is responsiblefor modeling the effect on the tool face control of a change in WOB or acorresponding WOB set point; a differential pressure impact model 666that is responsible for modeling the effect on the tool face control ofa change in differential pressure (DP) or a corresponding DP set point;a torque model 668 that is responsible for modeling the comprehensiverepresentation of torque for surface, downhole, break over, and reactivetorque, modeling impact of those torque values on tool face control, anddetermining torque operational thresholds; a tool face control evaluator672 that is responsible for evaluating factors impacting tool facecontrol and whether adjustments need to be projected, determiningwhether re-alignment off-bottom is indicated, and determining off-bottomtool face operational threshold windows; a tool face projection 670 thatis responsible for projecting tool face behavior for top drive 140, thetop drive oscillator, and auto driller adjustments; a top driveadjustment calculator 674 that is responsible for calculating top driveadjustments resultant to tool face projections; an oscillator adjustmentcalculator 676 that is responsible for calculating oscillatoradjustments resultant to tool face projections; and an autodrilleradjustment calculator 678 that is responsible for calculatingadjustments to autodriller 510 resultant to tool face projections.

FIG. 7 illustrates one embodiment of a steering control process 700 fordetermining a corrective action for drilling. Steering control process700 may be used for rotary drilling or slide drilling in differentembodiments.

Steering control process 700 in FIG. 7 illustrates a variety of inputsthat can be used to determine an optimum corrective action. As shown inFIG. 7 , the inputs include formation hardness/unconfined compressivestrength (UCS) 710, formation structure 712, inclination/azimuth 714,current zone 716, measured depth 718, desired tool face 730, verticalsection 720, bit factor 722, mud motor torque 724, reference trajectory730, vertical section 720, bit factor 722, torque 724 and angularvelocity 726. In FIG. 7 , reference trajectory 730 of borehole 106 isdetermined to calculate a trajectory misfit in a step 732. Step 732 mayoutput the trajectory misfit to determine a corrective action tominimize the misfit at step 734, which may be performed using the otherinputs described above. Then, at step 736, the drilling rig is caused toperform the corrective action.

It is noted that in some implementations, at least certain portions ofsteering control process 700 may be automated or performed without userintervention, such as using rig control systems 700 (see FIG. 7 ). Inother implementations, the corrective action in step 736 may be providedor communicated (by display, SMS message, email, or otherwise) to one ormore human operators, who may then take appropriate action. The humanoperators may be members of a rig crew, which may be located at or neardrilling rig 210, or may be located remotely from drilling rig 210.

Referring to FIG. 8 , one embodiment of a user interface 850 that may begenerated by steering control system 168 for monitoring and operation bya human operator is illustrated. User interface 850 may provide manydifferent types of information in an easily accessible format. Forexample, user interface 850 may be shown on a computer monitor, atelevision, a viewing screen (e.g., a display device) associated withsteering control system 168.

As shown in FIG. 8 , user interface 850 provides visual indicators suchas a hole depth indicator 852, a bit depth indicator 854, a GAMMAindicator 856, an inclination indicator 858, an azimuth indicator 860,and a TVD indicator 862. Other indicators may also be provided,including a ROP indicator 864, a mechanical specific energy (MSE)indicator 866, a differential pressure indicator 868, a standpipepressure indicator 870, a flow rate indicator 872, a rotary RPM (angularvelocity) indicator 874, a bit speed indicator 876, and a WOB indicator878.

In FIG. 8 , at least some of indicators 864, 866, 868, 870, 872, 874,876, and 878 may include a marker representing a target value. Forexample, markers may be set as certain given values, but it is notedthat any desired target value may be used. Although not shown, in someembodiments, multiple markers may be present on a single indicator. Themarkers may vary in color or size. For example, ROP indicator 864 mayinclude a marker 865 indicating that the target value is 50 feet/hour(or 15 m/h). MSE indicator 866 may include a marker 867 indicating thatthe target value is 37 ksi (or 255 MPa). Differential pressure indicator868 may include a marker 869 indicating that the target value is 200 psi(or 1.38 kPa). ROP indicator 864 may include a marker 865 indicatingthat the target value is 50 feet/hour (or 15 m/h). Standpipe pressureindicator 870 may have no marker in the present example. Flow rateindicator 872 may include a marker 873 indicating that the target valueis 500 gpm (or 31.5 L/s). Rotary RPM indicator 874 may include a marker875 indicating that the target value is 0 RPM (e.g., due to sliding).Bit speed indicator 876 may include a marker 877 indicating that thetarget value is 150 RPM. WOB indicator 878 may include a marker 879indicating that the target value is 10 klbs (or 4,500 kg). Eachindicator may also include a colored band, or another marking, toindicate, for example, whether the respective gauge value is within asafe range (e.g., indicated by a green color), within a caution range(e.g., indicated by a yellow color), or within a danger range (e.g.,indicated by a red color).

In FIG. 8 , a log chart 880 may visually indicate depth versus one ormore measurements (e.g., may represent log inputs relative to aprogressing depth chart). For example, log chart 880 may have a Y-axisrepresenting depth and an X-axis representing a measurement such asGAMMA count 881 (as shown), ROP 883 (e.g., empirical ROP and normalizedROP), or resistivity. An autopilot button 882 and an oscillate button884 may be used to control activity. For example, autopilot button 882may be used to engage or disengage autodriller 510, while oscillatebutton 884 may be used to directly control oscillation of drill string146 or to engage/disengage an external hardware device or controller.

In FIG. 8 , a circular chart 886 may provide current and historical toolface orientation information (e.g., which way the bend is pointed). Forpurposes of illustration, circular chart 886 represents three hundredand sixty degrees. A series of circles within circular chart 886 mayrepresent a timeline of tool face orientations, with the sizes of thecircles indicating the temporal position of each circle. For example,larger circles may be more recent than smaller circles, so a largestcircle 888 may be the newest reading and a smallest circle 889 may bethe oldest reading. In other embodiments, circles 889, 888 may representthe energy or progress made via size, color, shape, a number within acircle, etc. For example, a size of a particular circle may represent anaccumulation of orientation and progress for the period of timerepresented by the circle. In other embodiments, concentric circlesrepresenting time (e.g., with the outside of circular chart 886 beingthe most recent time and the center point being the oldest time) may beused to indicate the energy or progress (e.g., via color or patterningsuch as dashes or dots rather than a solid line).

In user interface 850, circular chart 886 may also be color coded, withthe color coding existing in a band 890 around circular chart 886 orpositioned or represented in other ways. The color coding may use colorsto indicate activity in a certain direction. For example, the color redmay indicate the highest level of activity, while the color blue mayindicate the lowest level of activity. Furthermore, the arc range indegrees of a color may indicate the amount of deviation. Accordingly, arelatively narrow (e.g., thirty degrees) arc of red with a relativelybroad (e.g., three hundred degrees) arc of blue may indicate that mostactivity is occurring in a particular tool face orientation with littledeviation. As shown in user interface 850, the color blue may extendfrom approximately 22-337 degrees, the color green may extend fromapproximately 15-22 degrees and 337-345 degrees, the color yellow mayextend a few degrees around the 13 and 345 degree marks, while the colorred may extend from approximately 347-10 degrees. Transition colors orshades may be used with, for example, the color orange marking thetransition between red and yellow or a light blue marking the transitionbetween blue and green. This color coding may enable user interface 850to provide an intuitive summary of how narrow the standard deviation isand how much of the energy intensity is being expended in the properdirection. Furthermore, the center of energy may be viewed relative tothe target. For example, user interface 850 may clearly show that thetarget is at 90 degrees but the center of energy is at 45 degrees.

In user interface 850, other indicators, such as a slide indicator 892,may indicate how much time remains until a slide occurs or how much timeremains for a current slide. For example, slide indicator 892 mayrepresent a time, a percentage (e.g., as shown, a current slide may be56% complete), a distance completed, or a distance remaining. Slideindicator 892 may graphically display information using, for example, acolored bar 893 that increases or decreases with slide progress. In someembodiments, slide indicator 892 may be built into circular chart 886(e.g., around the outer edge with an increasing/decreasing band), whilein other embodiments slide indicator 892 may be a separate indicatorsuch as a meter, a bar, a gauge, or another indicator type. In variousimplementations, slide indicator 892 may be refreshed by autoslide 514.

In user interface 850, an error indicator 894 may indicate a magnitudeand a direction of error. For example, error indicator 894 may indicatethat an estimated drill bit position is a certain distance from theplanned trajectory, with a location of error indicator 894 around thecircular chart 886 representing the heading. For example, FIG. 8illustrates an error magnitude of 15 feet and an error direction of 15degrees. Error indicator 894 may be any color but may be red forpurposes of example. It is noted that error indicator 894 may present azero if there is no error. Error indicator may represent that drill bit148 is on the planned trajectory using other means, such as being agreen color. Transition colors, such as yellow, may be used to indicatevarying amounts of error. In some embodiments, error indicator 894 maynot appear unless there is an error in magnitude or direction. A marker896 may indicate an ideal slide direction. Although not shown, otherindicators may be present, such as a bit life indicator to indicate anestimated lifetime for the current bit based on a value such as time ordistance.

It is noted that user interface 850 may be arranged in many differentways. For example, colors may be used to indicate normal operation,warnings, and problems. In such cases, the numerical indicators maydisplay numbers in one color (e.g., green) for normal operation, may useanother color (e.g., yellow) for warnings, and may use yet another color(e.g., red) when a serious problem occurs. The indicators may also flashor otherwise indicate an alert. The gauge indicators may include colors(e.g., green, yellow, and red) to indicate operational conditions andmay also indicate the target value (e.g., an ROP of 100 feet/hour). Forexample, ROP indicator 868 may have a green bar to indicate a normallevel of operation (e.g., from 10-300 feet/hour), a yellow bar toindicate a warning level of operation (e.g., from 300-360 feet/hour),and a red bar to indicate a dangerous or otherwise out of parameterlevel of operation (e.g., from 360-390 feet/hour). ROP indicator 868 mayalso display a marker at 100 feet/hour to indicate the desired targetROP.

Furthermore, the use of numeric indicators, gauges, and similar visualdisplay indicators may be varied based on factors such as theinformation to be conveyed and the personal preference of the viewer.Accordingly, user interface 850 may provide a customizable view ofvarious drilling processes and information for a particular individualinvolved in the drilling process. For example, steering control system168 may enable a user to customize the user interface 850 as desired,although certain features (e.g., standpipe pressure) may be locked toprevent a user from intentionally or accidentally removing importantdrilling information from user interface 850. Other features andattributes of user interface 850 may be set by user preference.Accordingly, the level of customization and the information shown by theuser interface 850 may be controlled based on who is viewing userinterface 850 and their role in the drilling process.

Referring to FIG. 9 , one embodiment of a guidance control loop (GCL)900 is shown in further detail GCL 900 may represent one example of acontrol loop or control algorithm executed under the control of steeringcontrol system 168. GCL 900 may include various functional modules,including a build rate predictor 902, a geo modified well planner 904, aborehole estimator 906, a slide estimator 908, an error vectorcalculator 910, a geological drift estimator 912, a slide planner 914, aconvergence planner 916, and a tactical solution planner 918. In thefollowing description of GCL 900, the term “external input” refers toinput received from outside GCL 900 , while “internal input” refers toinput exchanged between functional modules of GCL 900.

In FIG. 9 , build rate predictor 902 receives external inputrepresenting BHA information and geological information, receivesinternal input from the borehole estimator 906, and provides output togeo modified well planner 904, slide estimator 908, slide planner 914,and convergence planner 916. Build rate predictor 902 is configured touse the BHA information and geological information to predict drillingbuild rates of current and future sections of borehole 106. For example,build rate predictor 902 may determine how aggressively a curve will bebuilt for a given formation with BHA 149 and other equipment parameters.

In FIG. 9 , build rate predictor 902 may use the orientation of BHA 149to the formation to determine an angle of attack for formationtransitions and build rates within a single layer of a formation. Forexample, if a strata layer of rock is below a strata layer of sand, aformation transition exists between the strata layer of sand and thestrata layer of rock. Approaching the strata layer of rock at a 90degree angle may provide a good tool face and a clean drill entry, whileapproaching the rock layer at a 45 degree angle may build a curverelatively quickly. An angle of approach that is near parallel may causedrill bit 148 to skip off the upper surface of the strata layer of rock.Accordingly, build rate predictor 902 may calculate BHA orientation toaccount for formation transitions. Within a single strata layer, buildrate predictor 902 may use the BHA orientation to account for internallayer characteristics (e.g., grain) to determine build rates fordifferent parts of a strata layer. The BHA information may include bitcharacteristics, mud motor bend setting, stabilization and mud motor bitto bend distance. The geological information may include formation datasuch as compressive strength, thicknesses, and depths for formationsencountered in the specific drilling location. Such information mayenable a calculation-based prediction of the build rates and ROP thatmay be compared to both results obtained while drilling borehole 106 andregional historical results (e.g., from the regional drilling DB 412) toimprove the accuracy of predictions as drilling progresses. Build ratepredictor 902 may also be used to plan convergence adjustments andconfirm in advance of drilling that targets can be achieved with currentparameters.

In FIG. 9 , geo modified well planner 904 receives external inputrepresenting a well plan, internal input from build rate predictor 902and geo drift estimator 912, and provides output to slide planner 914and error vector calculator 910. Geo modified well planner 904 uses theinput to determine whether there is a more desirable trajectory thanthat provided by the well plan, while staying within specified errorlimits. More specifically, geo modified well planner 904 takesgeological information (e.g., drift) and calculates whether anothertrajectory solution to the target may be more efficient in terms of costor reliability. The outputs of geo modified well planner 904 to slideplanner 914 and error vector calculator 910 may be used to calculate anerror vector based on the current vector to the newly calculatedtrajectory and to modify slide predictions. In some embodiments, geomodified well planner 904 (or another module) may provide functionalityneeded to track a formation trend. For example, in horizontal wells, ageologist may provide steering control system 168 with a targetinclination angle as a set point for steering control system 168 tocontrol. For example, the geologist may enter a target to steeringcontrol system 168 of 90.5-91.0 degrees of inclination angle for asection of borehole 106. Geo modified well planner 904 may then treatthe target as a vector target, while remaining within the error limitsof the original well plan. In some embodiments, geo modified wellplanner 904 may be an optional module that is not used unless the wellplan is to be modified. For example, if the well plan is marked insteering control system 168 as non-modifiable, geo modified well planner904 may be bypassed altogether or geo modified well planner 904 may beconfigured to pass the well plan through without any changes.

In FIG. 9 , borehole estimator 906 may receive external inputsrepresenting BHA information, measured depth information, surveyinformation (e.g., azimuth angle and inclination angle), and may provideoutputs to build rate predictor 902, error vector calculator 910, andconvergence planner 916. Borehole estimator 906 may be configured toprovide an estimate of the actual borehole and drill bit position andtrajectory angle without delay, based on either straight lineprojections or projections that incorporate sliding. Borehole estimator906 may be used to compensate for a sensor being physically located somedistance behind drill bit 148 (e.g., 50 feet) in drill string 146, whichmakes sensor readings lag the actual bit location by 50 feet. Boreholeestimator 906 may also be used to compensate for sensor measurementsthat may not be continuous (e.g., a sensor measurement may occur every100 feet). Borehole estimator 906 may provide the most accurate estimatefrom the surface to the last survey location based on the collection ofsurvey measurements. Also, borehole estimator 906 may take the slideestimate from slide estimator 908 (described below) and extend the slideestimate from the last survey point to a current location of drill bit148. Using the combination of these two estimates, borehole estimator906 may provide steering control system 168 with an estimate of thedrill bit's location and trajectory angle from which guidance andsteering solutions can be derived. An additional metric that can bederived from the borehole estimate is the effective build rate that isachieved throughout the drilling process.

In FIG. 9 , slide estimator 908 receives external inputs representingmeasured depth and differential pressure information, receives internalinput from build rate predictor 902, and provides output to boreholeestimator 906 and geo modified well planner 904. Slide estimator 908 maybe configured to sample tool face orientation, differential pressure,measured depth (MD) incremental movement, MSE, and other sensor feedbackto quantify/estimate a deviation vector and progress while sliding.

Traditionally, deviation from the slide would be predicted by a humanoperator based on experience. The operator would, for example, use along slide cycle to assess what likely was accomplished during the lastslide. However, the results are generally not confirmed until thedownhole survey sensor point passes the slide portion of the borehole,often resulting in a response lag defined by a distance of the sensorpoint from the drill bit tip (e.g., approximately 50 feet). Such aresponse lag may introduce inefficiencies in the slide cycles due toover/under correction of the actual trajectory relative to the plannedtrajectory.

In GCL 900, using slide estimator 908, each tool face update may bealgorithmically merged with the average differential pressure of theperiod between the previous and current tool face readings, as well asthe MD change during this period to predict the direction, angulardeviation, and MD progress during the period. As an example, theperiodic rate may be between 10 and 60 seconds per cycle depending onthe tool face update rate of downhole tool 166. With a more accurateestimation of the slide effectiveness, the sliding efficiency can beimproved. The output of slide estimator 908 may accordingly beperiodically provided to borehole estimator 906 for accumulation of welldeviation information, as well to geo modified well planner 904. Some orall of the output of the slide estimator 908 may be output to anoperator, such as shown in the user interface 850 of FIG. 8 .

In FIG. 9 , error vector calculator 910 may receive internal input fromgeo modified well planner 904 and borehole estimator 906. Error vectorcalculator 910 may be configured to compare the planned well trajectoryto an actual borehole trajectory and drill bit position estimate. Errorvector calculator 910 may provide the metrics used to determine theerror (e.g., how far off) the current drill bit position and trajectoryare from the well plan. For example, error vector calculator 910 maycalculate the error between the current bit position and trajectory tothe planned trajectory and the desired bit position. Error vectorcalculator 910 may also calculate a projected bit position/projectedtrajectory representing the future result of a current error.

In FIG. 9 , geological drift estimator 912 receives external inputrepresenting geological information and provides outputs to geo modifiedwell planner 904, slide planner 914, and tactical solution planner 918.During drilling, drift may occur as the particular characteristics ofthe formation affect the drilling direction. More specifically, theremay be a trajectory bias that is contributed by the formation as afunction of ROP and BHA 149. Geological drift estimator 912 isconfigured to provide a drift estimate as a vector that can then be usedto calculate drift compensation parameters that can be used to offsetthe drift in a control solution.

In FIG. 9 , slide planner 914 receives internal input from build ratepredictor 902, geo modified well planner 904, error vector calculator910, and geological drift estimator 912, and provides output toconvergence planner 916 as well as an estimated time to the next slide.Slide planner 914 may be configured to evaluate a slide/drill ahead costcalculation and plan for sliding activity, which may include factoringin BHA wear, expected build rates of current and expected formations,and the well plan trajectory. During drill ahead, slide planner 914 mayattempt to forecast an estimated time of the next slide to aid withplanning. For example, if additional lubricants (e.g., fluorinatedbeads) are indicated for the next slide, and pumping the lubricants intodrill string 146 has a lead time of 30 minutes before the slide, theestimated time of the next slide may be calculated and then used toschedule when to start pumping the lubricants. Functionality for a losscirculation material (LCM) planner may be provided as part of slideplanner 914 or elsewhere (e.g., as a stand-alone module or as part ofanother module described herein). The LCM planner functionality may beconfigured to determine whether additives should be pumped into theborehole based on indications such as flow-in versus flow-backmeasurements. For example, if drilling through a porous rock formation,fluid being pumped into the borehole may get lost in the rock formation.To address this issue, the LCM planner may control pumping LCM into theborehole to clog up the holes in the porous rock surrounding theborehole to establish a more closed-loop control system for the fluid.

In FIG. 9 , slide planner 914 may also look at the current positionrelative to the next connection. A connection may happen every 90 to 100feet (or some other distance or distance range based on the particularsof the drilling operation) and slide planner 914 may avoid planning aslide when close to a connection or when the slide would carry throughthe connection. For example, if the slide planner 914 is planning a 50foot slide but only 20 feet remain until the next connection, slideplanner 914 may calculate the slide starting after the next connectionand make any changes to the slide parameters to accommodate waiting toslide until after the next connection. Such flexible implementationavoids inefficiencies that may be caused by starting the slide, stoppingfor the connection, and then having to reorient the tool face beforefinishing the slide. During slides, slide planner 914 may provide somefeedback as to the progress of achieving the desired goal of the currentslide. In some embodiments, slide planner 914 may account for reactivetorque in drill string 146. More specifically, when rotating isoccurring, there is a reactional torque wind up in drill string 146.When the rotating is stopped, drill string 146 unwinds, which changestool face orientation and other parameters. When rotating is startedagain, drill string 146 starts to wind back up. Slide planner 914 mayaccount for the reactional torque so that tool face references aremaintained, rather than stopping rotation and then trying to adjust to adesired tool face orientation. While not all downhole tools may providetool face orientation when rotating, using one that does supply suchinformation for GCL 900 may significantly reduce the transition timefrom rotating to sliding.

In FIG. 9 , convergence planner 916 receives internal inputs from buildrate predictor 902, borehole estimator 906, and slide planner 914, andprovides output to tactical solution planner 918. Convergence planner916 is configured to provide a convergence plan when the current drillbit position is not within a defined margin of error of the planned welltrajectory. The convergence plan represents a path from the currentdrill bit position to an achievable and desired convergence target pointalong the planned trajectory. The convergence plan may take account theamount of sliding/drilling ahead that has been planned to take place byslide planner 914. Convergence planner 916 may also use BHA orientationinformation for angle of attack calculations when determiningconvergence plans as described above with respect to build ratepredictor 902. The solution provided by convergence planner 916 definesa new trajectory solution for the current position of drill bit 148. Thesolution may be immediate without delay, or planned for implementationat a future time that is specified in advance.

In FIG. 9 , tactical solution planner 918 receives internal inputs fromgeological drift estimator 912 and convergence planner 916, and providesexternal outputs representing information such as tool face orientation,differential pressure, and mud flow rate. Tactical solution planner 918is configured to take the trajectory solution provided by convergenceplanner 916 and translate the solution into control parameters that canbe used to control drilling rig 210. For example, tactical solutionplanner 918 may convert the solution into settings for control systems522, 524, and 526 to accomplish the actual drilling based on thesolution. Tactical solution planner 918 may also perform performanceoptimization to optimizing the overall drilling operation as well asoptimizing the drilling itself (e.g., how to drill faster).

Other functionality may be provided by GCL 900 in additional modules oradded to an existing module. For example, there is a relationshipbetween the rotational position of the drill pipe on the surface and theorientation of the downhole tool face. Accordingly, GCL 900 may receiveinformation corresponding to the rotational position of the drill pipeon the surface. GCL 900 may use this surface positional information tocalculate current and desired tool face orientations. These calculationsmay then be used to define control parameters for adjusting the topdrive 140 to accomplish adjustments to the downhole tool face in orderto steer the trajectory of borehole 106.

For purposes of example, an object-oriented software approach may beutilized to provide a class-based structure that may be used with GCL900 or other functionality provided by steering control system 168. InGCL 900, a drilling model class may be defined to capture and define thedrilling state throughout the drilling process. The drilling model classmay include information obtained without delay. The drilling model classmay be based on the following components and sub-models: a drill bitmodel, a borehole model, a rig surface gear model, a mud pump model, aWOB/differential pressure model, a positional/rotary model, an MSEmodel, an active well plan, and control limits. The drilling model classmay produce a control output solution and may be executed via a mainprocessing loop that rotates through the various modules of GCL 900. Thedrill bit model may represent the current position and state of drillbit 148. The drill bit model may include a three dimensional (3D)position, a drill bit trajectory, BHA information, bit speed, and toolface (e.g., orientation information). The 3D position may be specifiedin north-south (NS), east-west (EW), and true vertical depth (TVD). Thedrill bit trajectory may be specified as an inclination angle and anazimuth angle. The BHA information may be a set of dimensions definingthe active BHA. The borehole model may represent the current path andsize of the active borehole. The borehole model may include hole depthinformation, an array of survey points collected along the boreholepath, a gamma log, and borehole diameters. The hole depth information isfor current drilling of borehole 106. The borehole diameters mayrepresent the diameters of borehole 106 as drilled over currentdrilling. The rig surface gear model may represent pipe length, blockheight, and other models, such as the mud pump model, WOB/differentialpressure model, positional/rotary model, and MSE model. The mud pumpmodel represents mud pump equipment and includes flow rate, standpipepressure, and differential pressure. The WOB/differential pressure modelrepresents draw works or other WOB/differential pressure controls andparameters, including WOB. The positional/rotary model represents topdrive or other positional/rotary controls and parameters includingrotary RPM and spindle position. The active well plan represents thetarget borehole path and may include an external well plan and amodified well plan. The control limits represent defined parameters thatmay be set as maximums and/or minimums. For example, control limits maybe set for the rotary RPM in the top drive model to limit the maximumRPMs to the defined level. The control output solution may represent thecontrol parameters for drilling rig 210.

Each functional module of GCL 900 may have behavior encapsulated withina respective class definition. During a processing window, theindividual functional modules may have an exclusive portion in time toexecute and update the drilling model. For purposes of example, theprocessing order for the functional modules may be in the sequence ofgeo modified well planner 904, build rate predictor 902, slide estimator908, borehole estimator 906, error vector calculator 910, slide planner914, convergence planner 916, geological drift estimator 912, andtactical solution planner 918. It is noted that other sequences may beused in different implementations.

In FIG. 9 , GCL 900 may rely on a programmable timer module thatprovides a timing mechanism to provide timer event signals to drive themain processing loop. While steering control system 168 may rely ontimer and date calls driven by the programming environment, timing maybe obtained from other sources than system time. In situations where itmay be advantageous to manipulate the clock (e.g., for evaluation andtesting), a programmable timer module may be used to alter the systemtime. For example, the programmable timer module may enable a defaulttime set to the system time and a time scale of 1.0, may enable thesystem time of steering control system 168 to be manually set, mayenable the time scale relative to the system time to be modified, or mayenable periodic event time requests scaled to a requested time scale.

Referring now to FIG. 10 , a block diagram illustrating selectedelements of an embodiment of a controller 1000 for performing surfacesteering according to the present disclosure. In various embodiments,controller 1000 may represent an implementation of steering controlsystem 168. In other embodiments, at least certain portions ofcontroller 1000 may be used for control systems 510, 512, 514, 522, 524,and 526 (see FIG. 5 ).

In the embodiment depicted in FIG. 10 , controller 1000 includesprocessor 1001 coupled via shared bus 1002 to storage media collectivelyidentified as memory media 1010.

Controller 1000, as depicted in FIG. 10 , further includes networkadapter 1020 that interfaces controller 1000 to a network (not shown inFIG. 10 ). In embodiments suitable for use with user interfaces,controller 1000, as depicted in FIG. 10 , may include peripheral adapter1006, which provides connectivity for the use of input device 1008 andoutput device 1009. Input device 1008 may represent a device for userinput, such as a keyboard or a mouse, or even a video camera. Outputdevice 1009 may represent a device for providing signals or indicationsto a user, such as loudspeakers for generating audio signals.

Controller 1000 is shown in FIG. 10 including display adapter 1004 andfurther includes a display device 1005. Display adapter 1004 mayinterface shared bus 1002, or another bus, with an output port for oneor more display devices, such as display device 1005. Display device1005 may be implemented as a liquid crystal display screen, a computermonitor, a television or the like. Display device 1005 may comply with adisplay standard for the corresponding type of display. Standards forcomputer monitors include analog standards such as video graphics array(VGA), extended graphics array (XGA), etc., or digital standards such asdigital visual interface (DVI), definition multimedia interface (HDMI),among others. A television display may comply with standards such asNTSC (National Television System Committee), PAL (Phase AlternatingLine), or another suitable standard. Display device 1005 may include anoutput device 1009, such as one or more integrated speakers to playaudio content, or may include an input device 1008, such as a microphoneor video camera.

In FIG. 10 , memory media 1010 encompasses persistent and volatilemedia, fixed and removable media, and magnetic and semiconductor media.Memory media 1010 is operable to store instructions, data, or both.Memory media 1010 as shown includes sets or sequences of instructions1024-2, namely, an operating system 1012 and surface steering control1014. Operating system 1012 may be a UNIX or UNIX-like operating system,a Windows® family operating system, or another suitable operatingsystem. Instructions 1024 may also reside, completely or at leastpartially, within processor 1001 during execution thereof. It is furthernoted that processor 1001 may be configured to receive instructions1024-1 from instructions 1024-2 via shared bus 1002. In someembodiments, memory media 1010 is configured to store and provideexecutable instructions for executing GCL 900, as mentioned previously,among other methods and operations disclosed herein.

The following disclosure explains additional and improved methods andsystems for drilling. In particular, the following systems and methodscan be useful to reduce dogleg severity in the wellbore and also obtainmore accurate placement of the wellbore. The following methods andsystems can be used to drill with less friction, which helps optimizerate of penetration and thus results in less cost to drill the well. Itshould be noted that the following methods may be implemented by acomputer system such as any of those described above. For example, thecomputer system used to perform the methods described below may be apart of the steering control system 168, a part of the rig controlssystem 500, a part of the drilling system 100, included with thecontroller 1000, or may be a similar or different computer system andmay be coupled to one or more of the foregoing systems. The computersystem may be located at or near the rig site, or may be located at aremote location from the rig site, and may be configured to transmit andreceive data to and from a rig site while a well is being drilled.Moreover, it should be noted that the computer system and/or the controlsystem for controlling the variable weight or force may be located inthe BHA or near the bit.

SWIFT Drilling

Accurate modelling of the drillstring and automation of the drillingprocess can be used to allow mud motor drilling to achieve any doglegseverity up to its maximum yield with minimal torque and drag. As usedherein, “SWIFT” stands for Sliding With Indexing For Toolface anddescribes a method whereby the normal slide/rotate patterns of mud motordrilling can be replaced by frequent, regular changes of toolface tofixed values which on average produce the desired dogleg severity in thedesired toolface plane. SWIFT drilling techniques can be used to drillthe wellpath with less tortuosity than a conventional slide/rotatedrilling pattern and can be used to disturb friction rotationally muchof the time during drilling and thus help reduce updrag.

When a simple slide/rotate drilling pattern is used, it is common todetermine a slide of the wellbore ‘ratio’ and then slide drill only foras much of a stand of pipe as is needed to achieve the desired wellborecurvature, and perform rotary drilling for the rest of the stand. Theissues with this are twofold. Firstly, the slide ratio which can bedefined as the Planned Dogleg Severity/Motor Yield can be only 50% oreven lower. For example, if the well plan requires a dogleg severity(DLS) of 8°/100 ft but the motor is capable of 16°/100 ft, the slideratio is 50% so the drilling only needs to slide 45 ft of every 90 ftstand of pipe to achieve 8°/100 ft on average. In practice, however, thegeometry delivered will be a 16°/100 ft curve for 45 ft andapproximately a straight line for 45 ft. This produces a peculiar resultwhen the subsequent surveys are processed. Conventional minimumcurvature techniques typically used to locate the wellbore will assume asingle arc from A to B producing the solid curved line shown on FIG. 11but in practice it is the dashed curve with short dashed and thestraight long dashed line that were drilled and clearly the position atB in FIG. 11 is different for the two paths. This positional error isknown as the Stockhausen Effect. The impact on the calculated wellpathposition over an entire build from vertical to horizontal is toaccumulate a total TVD Error of δTVD=0.5*Md Interval*(1−Slide Ratio).

If surveys are taken every 90 ft and the slide ratio is 0.5 (50%), onewould expect a final TVD error of 0.5*90*(1−0.5)=22.5 ft. If the rotarydrilling occurs before the slide drilling, the TVD error is −22.5 ft.Notice that the TVD error is not dependent on the build rate. Largerradii produce smaller errors when going from curve to straight but thelength over which the angle is generated is directly proportional to theradius so the net effect cancels out. This is not detectable in thesurveys and yet can be a significant error affecting geologicalmodelling and optimal positioning of the wellbore in the targetreservoir.

The additional sharp curvature in the wellbore has to be navigated byboth the drill pipe and casing in due course, and all downhole tools,including without limitation rotary steering systems, and can havesignificantly higher torque and drag effects than might be anticipatedfor a smoother curvature of the wellbore. This sharper curvature reducesthe penetration rate, adding to the cost of drilling the well. Further,the penetration rate when sliding is typically two to three times slowerthan when rotary drilling. In short, if the wellpath is smoother and thedrillstring is disturbed rotationally while drilling, the positioning ismore accurate, the penetration rate is higher, and the wellbore'scompletion is easier, and the risk of equipment damage or sticking isgreatly reduced.

SWIFT Example One: As a broad description, SWIFT drilling can be viewedas a repeated pattern of frequent toolface settings and spindlerotations to achieve the desired geometry of the wellbore. By slidingand rotating over very short lengths, the net effect is very similar toa smooth curve of a larger radius than the BHA would produce in purelyslide mode. This can be illustrated by way of examples.

If one wished to build the wellbore curve at 8°/100 ft with a BHAcapable of drilling 16°/100 ft, one could repeat a simple time-basedpattern as follows.

-   -   Estimate Reactive Torque (RT) for the desired weight on bit and        set the off bottom toolface to Target Toolface+RT.    -   Bring up the weight on bit and adjust the spindle until sliding        on target toolface begins.    -   Rotate at 5 RPM for 12 seconds (i.e., one 360° rotation).    -   Slide drill on highside for 12 seconds (observe toolface        delivered).    -   Repeat the preceding two steps.

Since we can predict the time required for a spindle change at thesurface to arrive downhole at the bit, we can start to adjust the onewrap change after that time to maintain target toolface. For example, ifthe toolface requires a movement to be 10 degrees right of what has beendelivered, the one wrap change would actually be 370 degrees instead of360 degrees. The effect of this process is that the Stockhausen Effecttakes place over much shorter intervals and accumulates to effectivelyzero. If the ROP value was 180 ft/hour, the progress made in 12 secondsis only 7 inches and the curve offset created with a 16°/100 ft DLS isonly 7 inches*sin(16*0.006)=1/100^(th) of an inch.

SWIFT Example Two: Suppose one requires a 3°/100 ft dogleg severity froma 16°/100 ft motor. For simplicity, we will assume constant ROP whetherrotating or sliding.

-   -   Estimate Reactive Torque (RT) for the desired WOB and set the        off bottom toolface to Target Toolface+RT.    -   Bring up the weight on bit and adjust the spindle until sliding        on target tooface, then    -   Slide for 30 seconds    -   Rotate at 5 RPM for 15 seconds (i.e., 1.25 wraps)    -   Slide for 41 seconds    -   Rotate at 5 RPM for 18 seconds (i.e., 1.5 wraps)    -   Slide for 41 seconds    -   Rotate at 5 RPM for 15 seconds (i.e., 1.25 wraps)    -   Repeat the preceding six steps

Only the first action is curving the wellbore on target. The first slidefor 41 seconds is cancelled out by the second slide for 41 seconds, andin every 160 seconds only 30 seconds of drilling is on target creating afinal yield of 3 (assuming constant ROP).

It can be seen therefore that any motor yield is possible by adjustingthe amount of time spent on each toolface. However, in practice whenchanges are made they will not be at constant RPM and the changes taketime to propagate downhole. The propagation predictions and reactivetorque predictions will not be accurate, the rock hardness will vary,and the toolfaces will be pulsed with a time delay. However SWIFTdrilling can provide additional benefits even when these uncertaintiesexist.

The variations in RPM, the time propagation down hole and the reactivetorque, rock hardness, and pulsing delays are likely to be consistentfor the duration of drilling a single slide in a single formation so theobserved errors can be measured and adjusted accordingly. If theinclination change and azimuth change achieved in a stand indicate adelivered toolface left of target or the pulsed toolfaces indicate aleft of target error, the primary stationary spindle position can beadjusted to the right accordingly. If the measured yield is too high,the timing on the offset toolfaces or the time spent rotating can beincreased, if too low, they can be increased. In some examples, thefollowing procedures can be automated in whole or in part by a computersystem such as any of those described above to implement the SWIFTmethod of drilling. Initially the system can use the prediction model toestimate the starting parameters at the start of a stand of pipe. Theseinclude;

-   -   Maximum ROP achievable;    -   Optimum Weight on Bit (WOB) for maximum ROP;    -   Expected Reactive Torque (RT) at Optimum WOB;    -   Expected Differential Pressure (DP) at Optimum WOB;    -   Spindle Change effect on downhole toolface against time; and    -   Block Velocity (BV) change effect on weight on bit delivered        against time.

Once a starting or initial set of parameters is input, received, ordetermined by the computer system, it can implement the SWIFT drillingtechnique and measure the total cycle time required to rotate from oneindex to the next and adjust the RPM or the slide time until the sliderotate balance matches the right values to produce the desired DLS. Insome examples, the SWIFT drilling technique is implemented by performingthe following steps:

-   -   Begin the slide assuming these values for the starting        parameters are correct.    -   Observe the toolface when stable weight on bit (WOB) is        achieved.    -   Observe the actual time taken for (WOB) to be delivered downhole        to the bit.    -   Determine the spindle change required to correct toolface to        target toolface (TgTf).    -   Apply the spindle change.    -   Apply a BV change to use RT to correct the anticipated toolface        error by the time the Block Velocity change arrives downhole at        the bit. This will bring the toolface to target toolface.    -   Repeat the previous step for the duration of the spindle        propagation time for the spindle change to reach the bit and the        weight on bit will balance to optimal while the toolface remains        approximately on target.    -   Once stable, use the differential pressure observed to estimate        downhole WOB.    -   Maintain as near constant (WOB) as reasonably as possible, index        the spindle by 1.25 wraps and measure actual time needed to make        this change. This is included in the accumulated rotary drill        time.    -   Hold Spindle for required time on 90° Right of TgTf.    -   Index Spindle by 1.5 wraps and hold for required time on 90°        Left of TgTf.    -   Index spindle by 1.25 wraps and hold for required time on TgTf.    -   Design time on each index to complete the cycle in a selected        distance, such as 10 ft.    -   Ensure the MWD system pulses the previous stable toolface (e.g.,        determined as a weighted average by stability) along with a time        stamp.    -   Use these toolfaces and the latest assessment of motor yield to        estimate well path position.    -   Determine a new target toolface and yield required and repeat        both the stabilization and indexing procedures as may be        required with an updated drillstring model based on the observed        values for the parameters.

It should be noted that, with a good model of the drillstring, surfacesensors can be used to provide data that in turn can be used to estimateother drilling parameters, which can be updated with data received fromdownhole while drilling. For example, a drillstring model can be used topredict or estimate a current toolface value based on surface torque andstandpipe pressure values, with the estimated toolface value updatedwhen a value for the toolface is received at the surface from downhole.The computer system can be programmed with the drillstring model so thatinitial parameters are updated based on measured values of variousdrilling parameters (e.g., WOB, ROP, RPM, surface torque, standpipepressure, differential pressure, toolface, etc.) and are used toautomatically estimate updated values as the drilling operationscontinue. In addition, the computer system can be programmed so that thedrillstring model is updated as drilling progresses to more accuratelyreflect the relationships of one or more drilling parameters to eachother. Although a few specific examples are provided here, it should benoted that any combination of these approaches can be used to create adrilling efficiency bias by either targeted drilling efficiency in atarget toolface range or by dwelling in a target toolface range tocreate non-uniform directional progress while reducing overalltortuosity. Examples are also provided with processing and adjustmentsto parameters being controlled from the surface based on a combinationof feedback from models, downhole sensors, and/or surface sensormeasurements. It is also possible to implement such a system within adownhole tool system above, below, or embedded into a downhole mud motorsystem. For instance, a telescoping WOB control system could be used ina complete downhole control loop implementation or in combination withsurface controls and sensors.

The computer system may also be programmed to apply a set of rules toprevent damage to the wellbore and/or the drilling rig. The rules mayinclude upper or lower threshold limits for various drilling parameters,or may include target parameter ranges. The computer system can monitorthe drilling parameters automatically while drilling progresses to checkif any of the parameters exceeds an upper limit, falls below a lowerlimit, or falls outside a target range. If such an event occurs, thecomputer system can be programmed to take corrective action, such as bygenerating an audible or visual alert, sending a message such as anemail or text message, and/or adjusting one or more drilling parametersor even shutting down drilling activity in circumstances in which adangerous condition is determined to exist.

Variable Weight Drilling

As used herein, “VWD” stands for Variable Weight Drilling whichdescribes a method whereby the BHA and drillstring are in constantrotation but as the BHA passes the desired toolface, the weight on bitis increased such that reactive torque slows the BHA revolutions downand on approach to the target toolface, the weight on bit is reduced.This procedure is similar to the SWIFT drilling procedure above, but inthis case the drillstring maintains rotational disturbance. Thistechnique can take advantage of processing in the MWD to smooth andpulse the shape of the toolface curve observed downhole. Like the SWIFTdrilling techniques described above, VWB techniques can be used tominimize tortuosity of the wellbore and can be used to minimize frictionand updrag.

In the curve shown in FIG. 12 , it can be seen that the toolfaceobservations when rotating are noisy with high frequency vibration, someoutliers in the data, and some evidence of a slow frequency drillstringvibration. By smoothing the data, a fitted function can be derived overthe period indicated by the bold line. The MWD data can be pulsed tosurface, including the phase and the key function parameters for thebest fit over the last several periods. The period itself will averageat the spindle period. This can be in the form: Absolute time at 0 forlast zero observation, with Polynormal parameters a, b and c describingthe fit curve in the form Toolface=at⁴+bt³+ct²+dt+e, where a, b, c, d,and e are the parameters and t is the time since the start of theperiod. One can assume the first observation is 0 and the last is 360,so d and e can be derived and need not be pulsed to the surface.

The effective yield on a target toolface when drilling on any othertoolface is the yield*cos(Toolface−Target Toolface).

The pulsed toolface values can be observed while rotating and fit acos(Toolface-Target Toolface) versus time smoothed curve to best matchthe frequency (but not the phase) of the spindle RPM, such as shown inFIG. 13 .

Allowing for the anticipated time required for a block velocity changeto propagate downhole to the bit if a variation in block velocity isapplied, one can superimpose a weight on bit pattern which can beconverted to an anticipated pattern of consequent reactive torque, suchas shown in FIG. 14 .

In FIG. 14 , the thin line shows the weight on bit pattern over time.With weight on bit rising, the reactive torque has a negative effect ontoolface. When the weight on bit is falling, this has a positive effecton toolface.

When these two effects on toolface are combined, a new waveform isgenerated for the toolface curve downhole and consequently for thecosine of the resultant toolface, such as shown in FIG. 16 .

FIG. 15 shows the effect of superimposing a weight on bit pattern on theoriginal toolface curve. The BHA spends more time close to the targettoolface and rapidly passes through the opposite quadrants. The functionparameters will change with the consequent effect on the cosine curves.

FIG. 16 shows the cos(toolface+Reactive Torque) and is the curve drawnwith a short dashed line with dot shading underneath, with the newaverage cos(toolface) shown by the long dashed line in FIG. 16 .

As indicated in FIG. 16 , the new average creates a yield bias in thedirection of the target toolface. With careful balancing of theamplitude and phase of the imposed weight on bit pattern, it is possibleto produce a symmetry that maximises yield in any desired direction orcancels it completely.

FIG. 17 shows the minimum yield when the weight on bit arrives 90degrees from the spindle phase.

FIG. 18 shows the maximum yield when weight arrives 180 degrees fromspindle phase, with the effect that when the toolface passes beyond thetarget, the weight on bit is increased to increase the reactive torqueand keep the toolface closer to target, and on approach to target theweight on bit is decreased to speed up progress towards the targettoolface. This approach maintains a rotary motion of the drillstring,thereby breaking friction and increasing ROP.

FIG. 19 shows a block diagram of the sequence of events for oneembodiment of VWD.

It is to be noted that the foregoing description is not intended tolimit the scope of the claims. For example, it is noted that thedisclosed methods and systems include additional features and can useadditional drilling parameters and relationships beyond the examplesprovided. The examples and illustrations provided in the presentdisclosure are for explanatory purposes and should not be considered aslimiting the scope of the invention, which is defined only by thefollowing claims.

What is claimed is:
 1. A computer system for controlling drillingoperations, the system comprising: a processor; a memory coupled to theprocessor, wherein the memory comprises instructions executable by theprocessor for: (a) determining values for a plurality of drillingparameters; (b) responsive to the determined values of the plurality ofdrilling parameters, setting a plurality of operating parameters forslide drilling in a wellbore; (c) determining an amount of change inweight on bit (WOB) during drilling; (d) responsive to a desired amountof change in WOB, determining an effect on toolface; (e) determining atime for WOB to be delivered to the bit; (f) determining a spindlechange required to modify the toolface to a toolface target; (g) sendinga signal to apply the determined spindle change; (h) sending a signal toapply a traveling block velocity change to correct an anticipatedtoolface error value when the traveling block velocity change manifestsat the bit; and (i) repeating step (h) during a time period for thetoolface to reach the toolface target.
 2. The computer system accordingto claim 1, wherein the instructions further comprise instructions torepeat steps (a)-(i) a plurality of times during drilling of a wellbore.3. The computer system according to claim 2, the system furthercomprising a database coupled to the processor, wherein the databasecomprises information regarding the plurality of drilling parameters andthe plurality of operating parameters.
 4. The computer system accordingto claim 3, wherein the plurality of drilling parameters comprise one ormore of a desired rate of penetration (ROP), a desired weight on bit(WOB) associated with a desired ROP, an expected reactive torqueassociated with the WOB, an expected differential pressure (DP)associated with the WOB, an expected effect on toolface associated witha spindle change, an expected effect on WOB associated with a blockvelocity change.
 5. The computer system according to claim 4, whereinthe instructions further comprise instructions for: (j) holding aspindle for a first predetermined time at a first predetermined value;and (k) holding the spindle for a second predetermined time at a secondpredetermined.
 6. The computer system according to claim 5, whereinfirst predetermined time and the second predetermined time are the same.7. The computer system according to claim 6, wherein the firstpredetermined value and the second predetermined value are 180 degreesapart.
 8. The computer system according to claim 5, further comprisinginstructions for performing steps (j) and (k) a plurality of timesduring the drilling of a wellbore.
 9. The computer system according toclaim 1, wherein a database or the instructions further comprise adrillstring model, and wherein the instructions further compriseinstructions for: (l) receiving data from a plurality of surface sensorsto monitor an effect of changes made and adjust surface commandsaccordingly; (m) responsive to the data from the plurality of surfacesensors subject to the drillstring model, estimating a plurality ofupdated values for the plurality of drilling parameters; and (n)responsive to the estimated updated values, repeating steps (b)-(h). 10.The computer system according to claim 9, further comprisinginstructions for repeating steps (l)-(n) a plurality of times whiledrilling the wellbore.
 11. A non-transitory, computer-readable mediumstoring a plurality of instructions that, when executed by one or moreprocessors of a computing device, cause the one or more processors toperform operations for controlling drilling operations comprising: (a)determining values for a plurality of drilling parameters; (b)responsive to the determined values of the plurality of drillingparameters, setting a plurality of operating parameters for slidedrilling in a wellbore; (c) determining an amount of change in weight onbit (WOB) during drilling; (d) responsive to a desired amount of changein WOB, determining an effect on toolface; (e) determining a time forWOB to be delivered to the bit; (f) determining a spindle changerequired to modify the toolface to a toolface target; (g) sending asignal to apply the determined spindle change; (h) sending a signal toapply a traveling block velocity change to correct an anticipatedtoolface error value when the traveling block velocity change manifestsat the bit; and (i) repeating step (h) during a time period for thetoolface to reach the toolface target.
 12. The non-transitory,computer-readable medium of claim 11, wherein the operations furthercomprise repeating steps (a)-(i) a plurality of times during drilling ofa wellbore.
 13. The non-transitory, computer-readable medium of claim12, wherein the operations further comprise storing informationregarding the plurality of drilling parameters and the plurality ofoperating parameters in a database.
 14. The non-transitory,computer-readable medium of claim 13, wherein the plurality of drillingparameters comprise one or more of a desired rate of penetration (ROP),a desired weight on bit (WOB) associated with a desired ROP, an expectedreactive torque associated with the WOB, an expected differentialpressure (DP) associated with the WOB, an expected effect on toolfaceassociated with a spindle change, an expected effect on WOB associatedwith a block velocity change.
 15. The non-transitory, computer-readablemedium of claim 14, wherein the instructions further compriseinstructions for: (j) holding a spindle for a first predetermined timeat a first predetermined value; and (k) holding the spindle for a secondpredetermined time at a second predetermined.
 16. The non-transitory,computer-readable medium of claim 15, wherein first predetermined timeand the second predetermined time are the same.
 17. The non-transitory,computer-readable medium of claim 16, wherein the first predeterminedvalue and the second predetermined value are 180 degrees apart.
 18. Thenon-transitory, computer-readable medium of claim 17, further comprisinginstructions for performing steps (j) and (k) a plurality of timesduring the drilling of a wellbore.
 19. The non-transitory,computer-readable medium of claim 11, wherein the instructions furthercomprise: (l) receiving data from a plurality of surface sensors tomonitor the effect of changes made and adjust surface commandsaccordingly; (m) responsive to the data from the plurality of surfacesensors subject to a drillstring model, estimating a plurality ofupdated values for the plurality of drilling parameters; and (n)responsive to the estimated updated values, repeating steps (b)-(h). 20.The non-transitory, computer-readable medium of claim 19, furthercomprising instructions for repeating steps (l)-(n) a plurality of timeswhile drilling the wellbore.